54 Oileld Review

Analyzing Hydrocarbons in the Borehole

Soraya BetancourtGo FujisawaOliver C. Mullins Ridgeeld, Connecticut, USA

Andrew CarnegieAbu Dhabi, United Arab Emirates (UAE)

Chengli DongAndrew KurkjianSugar Land, Texas, USA

Kre Otto EriksenStatoilStavanger, Norway

Mostafa HaggagAntonio R. JaramilloAbu Dhabi Company for Onshore OilOperationsAbu Dhabi, UAE

Harry TerabayashiFuchinobe, Kanagawa, Japan

CFA (Composition Fluid Analyzer), LFA (Live Fluid Analyzerfor MDT tool), MDT (Modular Formation Dynamics Tester)and PVT Express are marks of Schlumberger.For help in preparation of this article, thanks to SylvainJayawardane and Jiasen Tan, Edmonton, Alberta, Canada; Sudhir Pai, Rosharon, Texas, USA; IbrahimShawky, Abu Dhabi, UAE; and Tsutomu Yamate, Fuchinobe, Kanagawa, Japan.

A rapid evaluation of hydrocarbon uid composition is now available with a new

uid-sampling tool. The quality of samples taken for later analysis can be determined

before lling the sampling cylinder. The tool is sufciently sensitive to determine

compositional gradients within a formation.

Understanding crude oil composition early in thedevelopment process helps optimize resourceexploitation. Such information is now availablefrom a wireline tool, giving results in real timethat allow optimization of uid sampling basedon the measured in-situ composition.

An early determination of gas compositionand gas/oil ratio (GOR) may be necessary todecide whether to complete a well, or evenwhether to develop a eld at all. For example, theeconomics of developing elds that contain arich hydrocarbon gas and those that contain a

Near-infrared radiation

Absorption and excitation

Autumn 2003 55

high percentage of carbon dioxide [CO2] in thegas are markedly different. CO2 is highly corro-sive, so its presence can change requirements forowlines and surface equipment. In addition,commingling prospects with incompatible compositions may need to be avoided. Flowassurance also is impacted by problems withasphaltene, wax, hydrate and organic scalebuildup in owlines.1 The uid composition canrestrict allowable drawdown pressures and owrates to prevent uid dropout.

This article update presents recent develop-ments in uid analysis available with the MDTModular Formation Dynamics Tester.2 A newmodule, the CFA Composition Fluid Analyzer,provides a measurement of uid compositionfrom samples drawn directly from the formation.It discriminates the fractions of methane, lighthydrocarbons, heavy hydrocarbons, carbon dioxide and water present in a sample. The toolmakes this determination based on light absorp-tion and uorescence of the uids; results aretransmitted to surface in real time. Case studiesfrom the Middle East and the North Sea demon-strate the effectiveness of this new module.

Analyzing Oil and GasThe terms gas and oil describe the state of ahydrocarbon as vapor or liquid, but do not specify the chemical composition. A detailedmeasurement of the constituents of a hydro-carbon, as determined in a surface laboratory,can be used to predict the constituents of the gasand oil phasesas well as other physical properties like density and viscosityat varioustemperatures and pressures. These detailed laboratory measurements can take a long time toobtain. The new CFA tool, in conjunction withother modules on an MDT assembly, provides aquick determination of some of the componentsand indicates the degree of drilling-mud contamination before samples are taken for further analysis.

Hydrocarbon uids comprise a multitude ofconstituents ranging from single-carbon methaneto very long-chain carbon compounds, as well ascyclic, aromatic and other complex moleculessuch as asphaltenes and waxes. These con-stituents determine the phase behavior of a givenreservoir uid, which is often indicated using apressure-volume-temperature (PVT) phase dia-gram (above right).3 A hydrocarbon uid is in sin-gle phase if the pressure and temperature areoutside the phase envelope. At conditions withinthis envelope, two phases coexist. However, thephase composition changes within this two-phaseregion. Near the bubblepoint curve, the gas phase

is predominantly methane, but further into thetwo-phase region, more light and intermediatecomponents enter the gas phase.

Similarly, the rst liquid components to dropout after passing the dewpoint are the heaviercomponents; lighter components go into the liquid phase at conditions further from the dew-point curve. This phenomenon is important whensampling gas-condensate fluids: once a fluidenters the two-phase region, heavy componentsare lost into the liquid phase. This behavior isused in the CFA design to determine when a uidcrosses the dewpoint.

The pressure and temperature condition atwhich the bubblepoint and dewpoint curves meet is called the critical point. At that point,the density and composition of the liquid and gas phases are identical. The maximum tempera-ture at which two phases can coexist is termedthe cricondentherm.

Reservoir temperature is usually almost constantunless cold or hot uids are injectedinto the reservoirso most depleting reservoirsfollow a downward vertical path on a pressure-temperature phase diagram. If reservoir temper-ature is between the critical temperature andthe cricondentherm, liquid can drop out of thegas phase within the reservoir. These are termed

gas-condensate, or retrograde-condensate, reser-voirs. Gas in a reservoir with a temperaturegreater than the cricondentherm is termed a wetgas if liquid drops out because of pressure andtemperature decreases in the production system,or a dry gas if no liquid falls out in either thereservoir or production system.

Economic decisions early in an explorationproject often hinge upon characterizing the typeof hydrocarbon in a reservoir. This determinationis particularly true offshore, where an expensiveplatform infrastructure or subsea tiebacks mayneed to be designed to handle reservoir uids.Early hydrocarbon typing is also needed inremote areas where satellite elds may not be

Bubblepoint curve

Dewpoint curve

Temperature

Pres

sure

Critical point

Reservoir depletion

Cricondentherm

> A hydrocarbon phase envelope for a retrograde condensate. Between thebubblepoint and dewpoint curves, hydrocarbon uids are in two phases. Thelines of constant liquid mole fraction (dashed) meet at the critical point. Fluidsthat enter the two-phase region to the right of the critical point are termedretrograde condensates. Fluids at temperatures greater than the criconden-therm remain single phase at all pressures. If the initial reservoir condition oftemperature and pressure is above the phase envelope and between the crit-ical temperature and the cricondentherm, the uid goes through a dewpointand liquid drops out of the gas phase as the reservoir pressure declines. Thiscondition (vertical line) starts at initial reservoir condition, shown here at anarbitrarily chosen temperature and pressure.

1. Wasden FK: Flow Assurance in DeepwaterFlowlines/Pipelines, Deepwater Technology, World OilMagazine Supplement (October 2003): 3538.

2. Andrews RJ, Beck G, Castelijns K, Chen A, Cribbs ME,Fadnes FH, Irvine-Fortescue J, Williams S, Hashem M,Jamaluddin A, Kurkjian A, Sass B, Mullins OC, Rylander E and Van Dusen A: QuantifyingContamination Using Color of Crude and Condensate,Oileld Review 13, no. 3 (Autumn 2001): 2443.

3. For more on phase diagrams and pseudouids:Composing Pseudouids in: Alaka JO, Bahamaish J,Bowen G, Bratvedt K, Holmes JA, Miller T, Fjerstad P,Grinestaff G, Jalali Y, Lucas C, Jimenez Z, Lolomari T,May E and Randall E: Improving the Virtual Reservoir,Oileld Review 13, no. 1 (Spring 2001): 4445.

economic to produce unless a tieback congura-tion or additional facilities are built to marketthe gas.

Sound production practices also requireknowledge of uid-phase behavior. If reservoirpressure drops below the dewpoint, liquid con-densate drops out in the formation. At low saturation, liquid in the pore spaces is not mobile

and decreases the gas relative permeability. Twonegative economic impacts result: productivitydeclines and valuable condensate liquids are leftbehind in the reservoir. Pressure support throughgas or water injection often is required to keepreservoir pressure above the dewpoint. Similarpractices can be followed to keep an oil reservoirabove the bubblepoint to avoid gas breakout.

Miscible ood programs, such as reinjection ofseparator gases, can change the composition andphase behavior of the mixture of formation andinjected uids. Capturing reservoir uid samplesmay be necessary to understand this process also.

Fluid SamplingFor many years, the industry has evaluated uidsby collecting samples from a formation, bringingthem to surface, and analyzing them in a labora-tory that may be far from the wellsite. This process can be time-consuming and is subject toerrors in collection, handling or sample degrada-tion during transport.

The PVT Express onsite well-uid analysisservice is a recent advance in uid-propertydetermination. This system can deliver detaileduid-analysis data a few hours after samplesreach the surface. A unique minicell for PVTproperty determination allows onsite measure-ment of dewpoint pressure on gas-condensatesamples. The compact, modular, mobile labora-tory can be transported to any geographic location. Delays associated with sample ship-ment are eliminated. Fluid quality and uidproperties can be determined while the opportu-nity to obtain additional samples is still available. Decisions relating to additional wire-line formation testing or drillstem testing opera-tions can be made more quickly with the PVTExpress service.

Taking the next step, Schlumberger makessome uid properties evaluations downhole. TheLFA Live Fluid Analyzer for the MDT tool pro-vides a means to analyze in-situ fluids to determine when contamination from drillingmud has decreased sufciently to obtain a uidsample with acceptable quality.4 This minimizesthe time required to collect fluid samples,decreasing both rig costs and the risk of the toolbecoming stuck because it was on the formationfor too long.

The LFA module includes a channel speci-cally tuned to record the presence of methane,providing a means to obtain GOR.5 Downhole GORmeasurements help identify whether differentformations are compartmentalized. A samplingprogram can be directed to reveal compositionalvariation within a given compartment, helping tooptimize completion programs. Agreementbetween downhole, wellsite and laboratory crude-oil property measurements engenders condencein the derived uid properties.

The LFA channels also measure the oilscolor, which usually changes as drilling mud isushed out of the formation. A sophisticatedalgorithm indicates the cleanup time required to

56 Oileld Review

Optic

al d

ensi

ty

Wavelength, nm

Medium-weight oil

Water

Hydrocarbons

500 1000 1500 20000

1

2

3

4

CondensateCondensate

2.0

1600 1700 1800Wavelength, nm

Optic

al d

ensi

ty

1900 2000 2100

1.5

1.0

0.5

0.0

MethaneEthaneN-heptaneCarbon dioxide

> Visible and near-infrared absorption spectrum. As the wavelength increases, hydrocarbon opticaldensityor light absorptionis due to successively heavier and more complex molecules (bottom).Gas condensates and oils have different responses in the visible region. Hydrocarbon molecular-excitation bands appear at about 1700 nanometers (nm), where light interacting with hydrocarbonbonds induces molecular vibrations (top). Methane has a peak at the CH4 vibrational mode, andethane peaks at the CH3 mode. Longer-chain hydrocarbons, such as n-heptane, have many CH2bonds, but also have CH3 bonds at the ends of chains. The carbon dioxide excitation wavelength islonger than the hydrocarbon mode wavelengths. Water has two strong, broad absorption peaks,which can interfere with detection of the hydrocarbon excitation peaks (bottom).

Autumn 2003 57

obtain a representative formation-uid sample inthe MDT sample modules.6 This evaluation pre-qualifies fluid samples for more extensive analysis at the surface, provides basic uid-property data such as GOR and helps dene uidvariability at different depths. These measure-ments are critical for adjusting a sampling andanalysis plan while the MDT tool is in the bore-hole, which helps an operator realize maximumbenet of a logging run.

Gas-condensate reservoirs present specialchallenges for uid-sample collection. A sam-pling tool must apply a pressure differential topull uid out of the formation into its samplingchambers. If this drawdown is too large, the pres-sure can drop below the dewpoint and the sepa-rated liquid phase may be trapped in thereservoir. As a result, the sample collected willnot be representative. Even if the phase transi-tion occurs outside the formation, that is, theuid becomes multiphase within the tools probeand pumpout modules or in the owlines leadingto the sampling chamber, differences in uiddensity and viscosity and phase segregationwithin the tool can lead to an unrepresentativesample composition. This problem of a reservoiruid breaking into two phases is even moresevere when the samples are obtained at surfaceduring a drillstem test, which uses a larger pres-sure drawdown than a sampling tool on wireline.

The new CFA modulea joint development ofSchlumberger-Doll Research Center, Ridgeeld,Connecticut, USA; Schlumberger KabushikiKaisha Technology Center, Fuchinobe, Kanagawa,Japan; and Schlumberger Sugar Land ProductCenter, Sugar Land, Texas, USAwas designedspecically to detect dew formation as a secondhydrocarbon phase using a fluorescence detector. This is the rst downhole tool with dew-detection capabilities. With this capability,the module can differentiate between single- andmultiple-phase ow and can show when pressurein the tool drops below the dewpoint pressure.Used in combination with an LFA module, a CFAtool indicates the proper time and conditions forobtaining a uid sample, even in the difcultenvironment of gas-condensate reservoirs.

In addition to the uorescence detector, theCFA tool incorporates absorption spectrometersthat measure the opacity, or optical density, of auid at several wavelengths. These measure-ments distinguish several components of hydro-carbon uids, not only enhancing dew detection,but also providing a compositional analysis. This compositional analysis capability will be discussed first, with fluorescence detectiondescribed later in the article.

Evaluating Gas CompositionHydrocarbon molecules interact with light in thevisible and near-infrared wavelength band that issampled by the CFA spectrometers. Interactionwith electronic energy bands gives oils theircolor, with complex molecules absorbing morelight than simple ones (previous page).7 Oils witha signicant quantity of resins and asphaltenesare darker than oils containing primarily paraf-ns.8 Gas condensates tend to be relatively clear,with little electronic absorption.

A different type of interaction occurs in the near-infrared region, where light absorptionexcites molecular vibration. The type of molecular bond between carbon [C] and hydrogen [H] atoms determines the frequency ofabsorbed light. The dominant vibrational absorption interactions occur in three types ofmolecular congurations:9

a carbon atom surrounded by four hydrogenatoms, that is, CH4

a carbon atom with three hydrogen atoms,CH3

a carbon atom with two hydrogen atoms,CH2.Methane is the unique example of the rst

mode. Ethane is an example of the second case,because it contains two carbon atoms that areeach connected to three hydrogen atoms.However, longer-chain hydrocarbons are predom-inantly CH2 but also have the CH3 group ateach end of a chain. The CH2 group dominateslight absorption by such long-chain compounds,but there also is some CH3 absorption. Forexample, 77% of the carbon-hydrogen bonds of n-dodecane, a common parafn with 12 carbonatoms in a linear chain, are in CH2 groups.

There is a complication in the analysis ofhydrocarbon spectra: the absorption spectraoverlap. Spectral interpretation requires properaccounting for this overlap. These complexitiesare overcome in the CFA analysis by employing atechnique called principal component regres-sion. This mathematical procedure extracts max-imal information content in any dataset, in thiscase the vibrational spectra.

The CFA interpretation algorithm incorporatesve detectors to determine four components:10

methane, which is termed C1 in the CFA analysis 11

other hydrocarbon gases, termed C2-C5 hydrocarbon liquids, termed C6+ carbon dioxide, CO2.

Distinct spectral signatures can distinguishboth methane and carbon dioxide. The otherhydrocarbon gases are dominated by CH3, andCH2 groups dominate hydrocarbon liquids. Thus,

the principal component regression results areinterpretable in terms of spectral characteristics.

In the same part of the infrared spectrum,water has a broad and strong absorption peak.The presence of water can swamp the other sig-nals, particularly the CO2 signal. The CFA modulehas a detector tuned to the water vibrationalmode, indicating when the responses from theother detectors are inuenced by water.

The CFA tool is recommended for uids witha GOR exceeding 1000 scf/bbl [180 m3/m3],because uids with a lower GOR have a color signal that is strong enough to interfere with thevibrational-mode absorption peaks. This recom-mended range includes gases, gas condensates,volatile oils and some black oils.12

The following sections show how these com-positional measurements were used to detectinjected gas in a monitoring well and to discovera compositional gradient within the oil leg of areservoir with a gas cap.

4. Andrews et al, reference 2. 5. Mullins OC, Beck GF, Cribbs ME, Terabayashi T and

Kegasawa K: Downhole Determination of GOR onSingle-Phase Fluids by Optical Spectroscopy,Transactions of the SPWLA 42nd Annual LoggingSymposium, Houston, Texas, USA, June 1720, 2001,paper M.Dong C, Hegeman PS, Elshahawi H, Mullins OC,Fujisawa G and Kurkjian A: Advances in DownholeContamination Monitoring and GOR Measurement ofFormation Fluid Samples, Transactions of the SPWLA44th Annual Logging Symposium, Galveston, Texas,USA, June 2225, 2003, paper FF.

6. Mullins OC, Schroer J and Beck GF: Real-TimeQuantication of OBM Filtrate Contamination DuringOpenhole Wireline Sampling by Optical Spectroscopy,Transactions of the SPWLA 41st Annual LoggingSymposium, Dallas, Texas, June 47, 2000, paper SS.

7. For more on visible and near-infrared light interactionswith crude oil: Andrews et al, reference 2.

8. Nonhydrocarbon compounds found in oil, such as thosecontaining nitrogen, oxygen and sulfur, also contribute to color. Dark oils can contain large amounts of thesecomponents.

9. The dashes indicate a connection to other carbonatoms: CH3 connects to one carbon atom, and CH2connects to a carbon atom on each side of the indicatedcarbon atom.

10. Van Agthoven MA, Fujisawa G, Rabbito P and Mullins OC: Near-Infrared Spectral Analysis of GasMixtures, Applied Spectroscopy 56, no. 5 (2002): 593598.Fujisawa G, van Agthoven MA, Jenet F, Rabbito PA andMullins OC: Near-Infrared Compositional Analysis ofGas and Condensate Reservoir Fluids at ElevatedPressures and Temperatures, Applied Spectroscopy56, no. 12 (2002): 16151620.

11. In this terminology, the number following the letter Cindicates the number of carbon atoms in the compound.Thus, C1 is methane, with molecular formula CH4.

12. A standard correlation of oil type to GOR is that black oilGOR is less than 2000 scf/bbl [360 m3/m3]; volatile oilsrange from that value to 3300 scf/bbl [594 m3/m3]; thengas condensates extend to 50,000 scf/bbl [9006 m3/m3];and gases have GOR greater than 50,000 scf/bbl.

Detecting Injection GasThe CFA module was used in a gas-injection pilotproject that had been in operation for severalyears in an onshore carbonate reservoir in theUnited Arab Emirates (UAE). As part of an ongo-ing evaluation program, the operator, Abu DhabiCompany for Onshore Oil Operations (ADCO)drilled a new monitoring well to determine theprogress of the injected gas.13 An MDT samplingstring containing the CFA tool was equipped witha dual-packer module, a pumpout module, anLFA module and 18 single-phase multisamplechambers. Single-phase samples of sufficientquality for later, detailed laboratory analyseswere obtained from six different stations.

The CFA tool provided uid compositionalinformation prior to sample collection at the rstfour stations. The drilling uid was a water-basemud, so some water was detected during theanalysis. The characteristics of the pumpoutmoduledescribed in Detecting a MultiphaseCondition, page 60caused the water to appearas slugs passing the CFA window. The tool moni-tored the cleanup of the drilling uid prior to sampling.

The upper zone sample was virtually all oil(left). The second sample station clearly showeda high concentration of gas coming from the for-mation. The two lowest zones produced some gas.This indicated that, at the monitor well, the topzone was unswept, and the second zone had beenswept the most by the injected gas. The resultsdemonstrated that these two upper zones werenot in communication.

The CFA results were obtained after abouttwo hours of pumping to clean out drilling mud.After an additional two to three hours at eachstation, changes in the LFA color channels indi-cated that the uid had cleaned up enough totake a sample in a single-phase sampling cylin-der. These samples were analyzed in a laboratory,and the results match reasonably well with thereal-time CFA data. These results helped ADCOunderstand the ow characteristics and gas-injection efciency of their eld.

Discovering a Compositional GradientStatoil, the operator of a Norwegian Seaappraisal well, wanted to establish the gas/oilcontact (GOC) and oil/water contact (OWC) andobtain uid samples for laboratory analysis. Adrillstem test in a discovery well had not pro-vided conclusive uid-phase property data. Thiswas the only appraisal well drilled before developing facilities to process a complex, near-critical reservoir-uid system. Statoil felt it was

58 Oileld Review

10,26010,21510,17010,12510,08010,035

9990994599009855

8145810080558010796579207875783077857740

8145810080558010796579207875783077857740

8145810080558010796579207875783077857740

Lab result

Lab result

Lab result

Lab result

Highly Scattering Fluid

C1

Tool GOR

Gas/Oil Ratio

scf/bbl

A

B

C

D

75000

Laboratory GOR

C2C5Low

Medium

HighElapsedTime, s

C6+

CO2

Water Flag

Compositionpercent0 100

percent0 100

WaterVolumeFraction

Quality

> CFA uid composition in a UAE carbonate reservoir. The CFA result indi-cated that the upper zone, A, was unswept. The second station, B, had thegreatest concentration of the gas components, C1 and C2-C5, and the highestgas/oil ratio (GOR), indicating that the injected gas had swept this zone. Thetwo lower stations also had been partly swept by injected gas. Results fromsamples collected during this logging run were analyzed in a laboratory, con-rming the composition and GOR values measured by the CFA module.

Autumn 2003 59

important to obtain a good description of theuid properties within the reservoir.

A wireline triple combo log indicated 100 m[328 ft] of relatively featureless reservoir, exceptfor a possibly impermeable streak at aboutXY30 m (above). The density and neutron poros-ity logs did not indicate a crossover. Crossover isnormally a sign of a gas zone, but the formationand uid properties in this reservoir were suchthat no separation was seen, probably because ofhigh gas density, low oil density and invasion bywater-base mud ltrate. The formation resistivitywas uniform, but the resistivity due to the water-base mud in the invaded region indicated a prob-

able change in the ushed-zone water saturation,with a likely OWC at XY10.

Statoil next obtained pressure gradients inthe formation using an MDT tool to nd the dif-ferent uid sections. The MDT logging systemcomprised a probe module, a pumpout module, a CFA module, an LFA module and multiple sample-chamber modules. The probe module hada high-grade quartz pressure gauge.

Within the 100-m span identied by the wire-line logs, the operator obtained 25 pressure mea-surements. These data identied three differentpressure gradients corresponding to gas, oil andwater, all in hydraulic communication. However,

the pressure gradient alone was inadequate toresolve a compositional gradient in the hydrocar-bon zone. Statoil had investigated compositionalgrading at other locations around the world andwanted to study this oil leg in greater detail.14

Once the pressures were obtained, the opera-tor repositioned the tool string to analyze theformation uids using the CFA module and to col-lect samples in high-pressure sample bottlesfrom an area in the lower part of the oil leg. TheCFA module obtained a quick reading of samplecomposition before filling each sampling cylinder. The results, transmitted to surface inreal time, indicated that the uid compositionstabilized within 1000 to 2000 seconds, or 17 to33 minutes. The CFA compositional measure-ments typically were taken after an hour ofcleanup time. However, slugs of water-base mudcontinued to pass through the apparatus, and ittypically took more than two additional hours forthe mud contamination to become acceptablylow to obtain each sample for surface analysis.

Next, the probe was positioned in the gas cap.The GOR was high, with large concentrations ofC1 and C2C5 components. The optical densityat the color channel was almost zero in the gascap, consistent with the presence of a very light hydrocarbon system.

After obtaining a uid sample in the gas cap,the tool was repositioned to obtain a second sam-ple 14 m [46 ft] above the rst oil sample. Theoperator suspected there might be a compositionalgradient in the oil zone. The CFA results from thetwo oil stations indicated a signicantly higherGOR at the upper position. The color optical density also was less at the upper station, indicat-ing a greater content of gas components at thehigher position.

With this information, the operator was ableto change the logging plan immediately. Theprobe module was placed as close to theoil/water contact as possible, then as close to thegas/oil contact as possible. The CFA readingsover the full extent of the oil column conrmedthe existence of a uid compositional gradientand more than a 60% increase in GOR over about

13. Fujisawa G, Mullins OC, Dong C, Carnegie A,Betancourt SS, Terabayashi T, Yoshida S, Jaramillo ARand Haggag M: Analyzing Reservoir Fluid CompositionIn-Situ in Real Time: Case Study in a CarbonateReservoir, paper SPE 84092, presented at the SPEAnnual Technical Conference and Exhibition, Denver,Colorado, USA, October 58, 2003.

14. Hier L and Whitson CH: Compositional GradingTheory and Practice, paper SPE 63085, presented at the SPE Annual Technical Conference and Exhibition,Dallas, Texas, USA, October 14, 2000. For another compositional-gradient example: MetcalfeRS, Vogel JL and Morris RW: Compositional Gradientsin the Anschutz Ranch East Field, paper SPE 14412,SPE Reservoir Engineering 3, no. 3 (August 1988):10251032.

XX602.7140 1.720 p.u.API

Neutron PorosityGamma Ray

XX80

XY00

XY20

XY40

XY60

XY80

00.6 g/cm3Bulk Density

60WaterOil

Gas0 in. 385375 bar

Invaded-Zone Diameter

10,0000.1 ohm-m

Invaded-Zone Resistivity

MDT Pressure

10,0000.01 ohm-m

Formation Resistivity

80000 scf/bbl

C6+

C2C5

Water

C1

Tool GOR

80000 scf/bblLaboratory GOR

30Optical Density

Gas/oilcontact

2

5

3

1

4Oil/watercontact

> Compositional gradient in a North Sea well. Gamma ray (Track 1), bulk density and neutron porosity(Track 2), and formation resistivity (Track 3) logs indicate a relatively featureless zone of about 100 m[328 ft]. A thin, possibly impermeable zone exists at about XY30. The invaded-zone resistivity (Track 3)implies a water zone up to XY10, with a transition zone up to about XX95 and perhaps a third zoneabove XX75. The pressure measurements (Track 4) conrm three gradients, with a gas/oil contact atXX75 and an oil/water contact at XY10. Both optical density from the CFA color channel and gas/oilratio (GOR) (Track 5) show a gradient in composition, which is also seen in the CFA compositionalanalysis (Track 4). The numbers to the left of the CFA compositions indicate the sampling order in thewellbore. The thin bars below each CFA result are later laboratory results, which were scaled toexclude the water fraction measured by the CFA tool, allowing direct comparison of the hydrocarboncomponents. Laboratory GOR measurements (Track 5) also conrm the compositional gradient,although the magnitude is somewhat different from the CFA result.

a 32-m [105-ft] interval within the oil column.Fluid samples taken at each of these points andlater analyzed in a laboratory confirmed a compositional gradient.

Finding this gradient without the real-timeCFA analysis would be unlikely. First, small dif-ferences between samples in a laboratory oftenare interpreted as reecting sampling difcultiesrather than uid-property variations. Second, acompany would not be likely to position a tool atfour separate heights in this oil leg without someprior evidence of the presence of a gradient.

For Statoil, the important point was that theexistence of a compositional gradient within theoil leg was noticed and conrmed in real time.This allowed the operator to adjust the MDT sampling program to identify appropriate uidsampling depths and collect sufcient quantitiesof samples for complete reservoir uid description.

Knowing that there was a compositional gradientin the formation and knowing the expected rangeof GOR helped the company develop a wellboredrawdown strategy to optimize production.

Because the operator planned to develop theeld using horizontal wells, placement of thewells in relation to the gas/oil and water/oil con-tacts was crucial. An MDT permeability test per-formed during this testing sequence providedadditional information for well placement.

The in-situ properties determination pro-vided by the combination of the CFA and LFAmodules assured that quality samples wereobtained in the sampling cylinders. Since theproduced uids from this eld will be tied in toother elds, a quality uid compositional analy-sis and determination of compatibility with theother uids were important for ow assurance.

Subtle changes in composition can be easilyobscured if the uid passing through the detec-tors has separated into two phases. This canoccur if the drawdown pressure is too great. Theuse of uorescence is key to detecting when auid passes through its dewpoint.

An Aromatic Afterglow Aromatic hydrocarbons uoresce. The distin-guishing characteristic of uorescence is thatthere is a brief time delay between light absorp-tion and its reemission, and that the reemissionoccurs at a lower energythat is, a longer wave-lengththan the absorbed light (left).15

The CFA module incorporates a uorescencedetection unit (FDU) along the owline, about7 cm [3 in.] from the absorption spectrometer.Since they are close together, the two types ofdetector sample essentially the same uid. Thisallows the two measurements to be used simulta-neously to evaluate uids.

The FDU shines blue light onto a window inthe ow tube. One detector tuned at the sourcewavelength is placed at the reection angle. This provides a measure of direct reection oflight, reducing the possibility of false-positive uorescence detection. Two other detectors inthe FDU record the intensity and spectrum of the uorescence.

The FDU is particularly sensitive to uores-cence from uid on the surface of the ow-tubewindow. Dew formation often causes a liquidcoating on the ow-tube surfaces. When the uidis in a single phase, the detector measures theproperties of the uid owing near the window.Once the pressure drops below the dewpoint, liquid drops out of solution and condenses. Thecondensed liquid phase wets the detector win-dow, so the uorescence detector is most sensi-tive to the properties of the liquid phase. Sincethe heavy ends are enriched in the liquid phase,the FDU is sensitive to the presence of a liquidphase dropping out from a gas condensate. Thismakes it an excellent tool for detecting when auid drops below its dewpoint.

Detecting a Multiphase Condition The rst use of an FDU in the eld showed thatthe drawdown pressure being used at that sampling station was too large, generating a two-phase condition. The operator moved to anotherlocation a few centimeters away and resampled,this time obtaining a good sample. This sectiondescribes how the fluids separated in thepumpout module and how the FDU detected thistwo-phase condition caused by excessive draw-down at the rst location.

60 Oileld Review

Excitation

Fluorescence channel 1

Gas condensate

Light oilFluorescencechannel 2

Wavelength

Fluo

resc

ence

inte

nsity

Fluid flow

Reflectiondetector

Fluorescencechannel 1

Fluorescencedetection unit

Fluorescencechannel 2

Blue lightsource

Spectrometer

Lamp

Water

> Detecting uorescence. The uorescence detector and spectrometer areabout 7 cm [3 in.] apart along the CFA owline (bottom). In the uorescencedetection unit, a blue light source reects from a sampling window into adetection channel tuned to the same wavelength. The excitation beam isreemitted at longer wavelengths. Two other channels are tuned to detect thishydrocarbon uorescence over two broad ranges of wavelengths. Most of thesignal from condensates occurs in the rst of these two detectors (top).

Autumn 2003 61

During an MDT logging run, a probe sealsagainst the formation, then the pump pulls uidfrom the formation into the tool. Ideally, thedrawdown will be sufcient to remove the uidfrom the formation, but not so much as to dropthe uid below its dewpoint pressure. However,both the formation permeability and the differen-tial between dewpoint pressure and formationpressure are unknown or poorly known beforemost MDT jobs in exploration wells begin. In fact,determining the dewpoint is one of the main rea-sons for obtaining uid samples. Without knowingpermeability and dewpoint pressure, establishinga proper drawdown pressure to keep a gas in single phase is difcult. The FDU on the CFA toolprovides a check of this condition in situ.

When water may be present in the owline,the CFA unit should be placed downstream of thepumpout module to avoid continuous swampingof the longer wavelength absorption spectrome-ters by the strong water-absorption peak. Thewater is still present in the owlines in this con-guration, but the residence time in the pump issufcient for phase segregation to occur. Thus,the water, oil and gas phases will ow throughthe spectrometers separately (right). On thedownstroke, the lower part of the pump lls fromthe formation, and the upper part discharges tothe owline. The discharge point is at the bottomof the upper pump chamber, so the rst uidpumped out is water, followed by oil, then gas. Onthe upstroke, the chambers reverse function.Now, the lower chamber discharges to the ow-line, but this time does so from the upper part of the chamber. The rst uid expelled is gas, followed by oil, then water.

The CFA tool clearly distinguishes owingphases using the water and hydrocarbon vibra-tional-energy absorption peaks and the mainFDU fluorescence channel. The hydrocarbonvibrational channels provide an indicator of theamount of gas passing through the owline whenthe ratio of C1 to C6+ is high. The FDU is sensi-tive to the presence of a liquid hydrocarbonphase. Thus, a plot of these three quantitieswater absorption, C1/C6+ ratio and the main uorescence channelshows the three phasespassing through the owline.

This procedure indicated three-phase owduring sampling of a gas cap in a North Sea well.In this case, the operator suspected that the gas

cap might contain a retrograde condensate. Thegas was near a saturated condition, and thepumpout unit drew the pressure down to about25 bar [370 psi] below formation pressure.Because a large drawdown was used to pump theuids out of the formation, two hydrocarbonphases were observed; a sample taken from thisdepth would be invalid because of a high likeli-hood of formation-uid damage at this point.After moving the MDT string a few centimeters toobtain an unaffected uid sample, the operatorfound this new sample contained more liquidthan the rst. Detecting the inappropriate sam-pling condition and moving to a new location waspossible because of the real-time CFA results.

Real-Time AdvantagesCapabilities provided by the FDU are being incorporated into real-time CFA services,increasing the sensitivity for detecting phasetransitions and providing additional informationabout in-situ uid compositions.

The ability to distinguish methane and lighthydrocarbons from heavier hydrocarbons greatlyincreases the amount of information available inreal time from gas-condensate reservoirs. Thisdetermination allows an operator to quicklymake important economic decisions about areservoir. The operator can then follow up withmore extensive measurements in a surface laboratory, using samples whose quality has been assuredbefore collectionusing these innovative downhole sampling tools. MAA

15. One way for a molecule to decay from an excited stateis by emitting a photon. If some of the excitation energyhas dissipated, for example through collision, the reemit-ted light is at a lower energy than the absorbed light.

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> Detecting multiple phases downstream of the pumpout module in a North Sea well. The pumpoutmodule is a reciprocating pump with two separate chambers sharing one piston. When the pumpoutmodule strokes down (top left), a multiplex valve directs uid from the formation into the lower chamberand from the upper chamber into the owline. On the upstroke, the multiplex valve switches the inletand outlet sources (top right). The CFA module, which is downstream of the pump, detects threephases. The chart (middle) compares signals from the water vibrational channel, from the main uorescence channel that indicates liquid oil, and from the C1/C6+ ratio that indicates gas. On thedownstroke, water is expelled rst, followed by oil, then gas (assuming all are present, as they arehere). On the upstroke, the order is reversed. The color bar indicates the primary ow contributor (bottom). This uid sample came from a gas-condensate zone, and the separation of the uid into gasand liquid phases indicated the drawdown was too large.